CA1301443C

CA1301443C - Carbon dioxide systems for hydraulic fracturing of hydrocarbon reservoirs

Info

Publication number: CA1301443C
Application number: CA000529413A
Authority: CA
Inventors: Carlos Fernando Barrientos-Penna; Robert Chauncey Greenhorn; Cheung Kien Li Kwok Cheong
Original assignee: Canadian Fracmaster Ltd
Current assignee: Canadian Fracmaster Ltd
Priority date: 1987-02-10
Filing date: 1987-02-10
Publication date: 1992-05-26
Anticipated expiration: 2009-05-26

Abstract

ABSTRACT
"Carbon Dioxide Systems for Hydraulic Fracturing of Hydrocarbon Reservoirs"
A method of fracturing a subterranean formation with a fracturing fluid comprising as a first phase, from 75% to 99.5% by weight of liquid carbon dioxide and, as a second phase, an organic liquid which is not miscible with liquid CO2 and a selected surfactant. The two-phase mixture or combination is prepared on the surface and injected, with or without added proppant, into the subterranean formation. The fluid demonstrates substantially improved viscosity over other known carbon dioxide-based fracture systems.

Description

13(~ 3 BACKGROUND OF THE INVENTION
This invention relates to novel two-phase systems suitable for use in the hydraulic fracturing of hydrocarbon reservoirs. More particularly, this invention relates to 5 new, liquid carbon dioxide-containing combinations or mixtures useful as fracturing fluids for deep gas wells and oil wells which mixtures demonstrate increased viscosity over conventional carbon dioxide fracturing fluids.
The treatment of subterranean formations penetrated by a 10 well bore to stimulate the production of hydrocarbons therefrom has long been known in the art. One of the most common methods of increasing productivity of a hydrocarbon-bearing formation is to subject the formation to a fracturing treatment. This treatment is effected by injecting a liquid, 15 gas or two-phase fluid which generally is referred to as a fracturing fluid down the well bore at sufficient pressure and flow rate to fracture the subterranean formation. A
proppant material, such as, sand, fine gravel, sintered bauxite, glass beads or the like can be introduced into the 20 fractures to keep them open. The propped fracture provides larger flow channels through which an increased quantity of hydrocarbon can flow, thereby increasing the productive capability of a well.
Carbon dioxide ~C02) has been used for over twenty years 25 as a component of fluids used for hydraulic fracturing and numerous fracturing methods using this compound have been proposed. Thus, U.S. Patent No. 3,368,627 describes the use of a mixture of liquefied C02 and a liquefied hydrocarbon, such, as propane as a fracturing fluid. In U.S. Patent No.
30 3,310,112, the use of a gelled hydrocarbon slurry or emulsion in admixture with liquid C02 is proposed for the same purpose. U.S. Patent No. 3,396,107 describes a fracturing composition consisting of a liquid C02 and water mixture.
U.S. Patent No. 3,623,552 describes a well displacement 35 process wherein liquid C02 is injected into a formation in three phases or stages, each phase having a different density. In U.S. Patent No. 3,664,422, the use of liquid C02 in combination with a gelled alcohol is proposed for use in a well treating system. U.S. Patent No. 3,765,488 discloses the use of a fracturing fluid comprising liquid C02 mixed with a gelled alcohol, using a specific hydroxyalkyl cellulose gelling agent. In U.S. Patent No. 3,842,910, a particular well-treating method making use of liquid C02 is described. U.S. Patent No. 3,954,626 provides a well 10 treating composition comprising liquid C02, alcohol and a hydroxy-propyl methylcellulose gelling agent. U.S. Patent No. 4,519,455 describes a fracturing fluid containing liquid C2 and up to 70% by weight of an immiscible second phase liquid, which is preferably ethylene glycol, which fracturing 15 fluid is formed in situ in the formation.
While all of the above noted inventions are meritorious, none has completely alleviated the problems associated with the use of liquid C02 as a well-fracturing fluid. Although liquid C02 is a near ideal fracturing fluid, since it 20 vaporizes in situ, it nevertheless has a very low viscosity and, hence, must be combined with, for example, a gelled alcohol or similar material in order to support a propping agent and to provide a suitable fracture width in all but shallow gas wells. The presence of, for example, hydroxy-25 alkyl cellulose thickening agents, however, often results inthe deposit of an undesirable residue in the rock fissures.
Furthermore, hydroxyalkyl cellulose thickeners are cross-linked only with difficulty and many species are not compatible with liquid C02. Foaming of the liquid mixtures 30 during pumping may also present problems when such thickeners are present. The description "thickened liquid C02" found in the prior patent literature tends to be misleading since it is the alcohol which is gelled or thickened and which is then diluted by the presence of the liquid C02. What is required 35 in the industry is a well fracturing fluid which is 13(~ 43 sufficiently viscous to be delivered under pressure into a subterranean formation at a high pumping rate, which will not boil or foam during pumping, which carries a suspended propping agent without difficulty and which will completely degrade in the underground location without leaving any interfering residue in the formation.
SUMMARY OF THE INVENTION
The present invention provides novel high phase volume liquid C02 fluids having a higher than expected viscosity 10 suitable for use for the hydraulic fracturing of hydrocarbon reservoirs and placing of proppant therein. Generally speaking, the novel fluids of the invention are combinations or mixtures of liquid C02 and an organic liquid which is not miscible with liquid C02, such as, crude oil or diesel oil or 15 non-aqueous organic liquids, such as, glyceryl triacetate, alcohol and the like. More particularly, they are mixtures containing from 75% to 99.5% by weight of liquid C02 and from 0.5% to 25% by weight of a second phase which comprises an oil or other non-miscible liquid organic containing from 0.1%
20 to 10% by weight of surfactant. The surfactant chosen will be appropriate to the nature of the organic liquid employed.
DESCRIPTION OF PREFERRED EMBODIMENTS
Mixtures or combinations that have been found particularly useful from the standpoint of desired viscosity 25 are those containing from 75% to 99.5% by weight of liquid C2 and from 0.5% to 25% by weight of a second phase comprising (a) crude or diesel oil containing from 0.1% to 10% by weight of an ethoxylated resin acid surfactant; or (b) solutions of triolein, a mixture of a homologous series of 30 alkoxy-terminated polyglycols (Selexol - Reg. TM) containing from 0.1% to 10% of an ammonium linear alcohol ethoxysulphate surfactant (Fenopon CD-128 - Reg. TM); or (c) solutions of triolein, glycol ethers, such as, for example, triglyme and Fenopon; or (d) solutions of alcohols having up to 30 carbon 35 atoms, such as, for example, oleyl alcohol, diesel oil and a 1301~43 selection of sorbitan oleate surfactants (Span - Reg. TM); or (e) solutions, such as, in (d) above wherein part of the alcohol is replaced by an organic acid having up to 30 carbon atoms, such as, for example, oleic acid.
S To illustrate the mixtures and combinations of this invention, some of which may be in the form of emulsions, and not by way of limitation, the following examples are provided.
EXAMPLE I
The following procedure was used to prepare mixtures of liquid C02 and diesel or crude oil or other non-aqueous solution.
Two Jerguson gauges were set up with a Koch (Reg. TM) motionless mixer placed in between them. The required 15 amounts of oil and surfactant were put into the gauges first and then the required volume of liquid C02 was added. The ingredients were pumped through the motionless mixer a number of times to form the emulsion-like mixtures. Once formed, the mixtures were introduced directly into the couette of a 20 Rheometric Pressure Rheometer for viscosity measurements.
During the addition, the couette was kept spinning at at least 1000 sec 1 to maintain the emulsified state. When addition was complete, a pre-programmed shear rate scan was run and viscosity versus shear rate and/or time rate curves 25 were generated. Results are illustrated in Tables I and IA
where concentrations of ingredients are given as parts by volume. - -. ~

13~14~3 TABLE I

Ethoxylated resin acid 1 1 surfactant Liquid C02 90 85 BO
Beaverhill Lake Crude 10 15 20 (parts by volume) Shear rate lSec 1) Viscosity (cp) 250 2.3 2.9 4.0 500 1.4 2.6 2.9 750 1.6 2.6 2.8 1000 1.5 2.2 2.2 1250 1.4 2.2 1.7 1500 0.6 1.7 0.7 1750 0.8 1.1 0.8 2000 0.9 1.5 1.0 I
TABLE IA
. .
Ethoxylated resin acid 1 1 surfactant Liquid C02 90 85 80 Diesel Oil 10 15 20 (parts by volume) Shear rate (Sec 1) Viscosity (cp) 500 _ 1.1 _ 750 _ 0.79 iOOQ _ 0.53 0.61 1250 _ 0.48 0.62 1500 _ 0,56 0.87 1750 0.45 0.69 1.04 2000 0.42 0.58 1.00 130~43 In all cases, the viscosity of the mixtures was found to be higher than would be expected from simple dilution behaviour.
EXAMPLE II
A field trial of a mixture of liquid C02/diesel oil of 5 85/15, stabilized by addition of part of an 8 mole ethoxylate resin acid was successfully run. 78 M3 of the mixture was used to hydraulically fracture a 1330 meter gas well. 15,000 Kg of proppant was placed at proppant addition rates of up to 600 kg/m3. Pumping pressure due to friction was 50% of that 10 usually encountered when using unadulterated liquid C02.
EXAMPLE III
A solution of 47% triolein, 47% of a mixture of a homologous series of alkoxy-terminated polyglycols Selexol and 6% Fenopon was used to make a mixture having a liquid C02/second phase ratio of 95/5. The viscosity of this mixture was 24 cp at -15C at 500 sec 1 of shear. Other glycol ethers were tested (diglyme, triglyme, etc.) but the visco~ities were significantly lower.
EXAMPLE IV
Solutions of 47% oleyl alcohol, 47% diesel oil and 6%
sorbitan oleate surfactants (Spans) were used as in Example III to make mixtures having a liquid C02/second phase ratio of 98/2. Viscosities ranged from 4 to 13 cp depending on the quality of the oleyl alcohol used. The use of decanol or 25 oleic acid to replace the oleyl alcohol gave lower viscosities (1.5 cp), still at a concentration of 98% liquid C02. Replacement of part of the oleyl alcohol by oleic acid results in a controllable viscosity change from 10 to 26 cp, while maintaining the liquid C02 at 98%, (e.g. replacement of 30 10% of oleyl alcohol gave 10 cp, 20% gave 26 cp, 30 and 40%
gave 7 cp each).
EXAMPLE V
The stability of the system is demonstrated by the following example. 98 Parts by weight of liquid carbon 35 dioxide when added to 2 parts by weight of a solution 13V1~43 containing 38.4% by weight of oleyl alcohol, 9.6~ by weight of oleic acid, 47% by weight of diesel oil and 6% by weight of sorbitan oleate surfactant gave a viscosity of 20.3 centipoise at -20.2C and 1000 psi. The viscosity of the s mixture remained stable for at least 20 minutes (20 cp at -20C, 1000 psi at 19.7 minutes).
EXAMPLE VI
To demonstrate the non-damaging characteristics of the fracturing fluids of the present invention, the composition 10 of Example V was injected through 25 cm x 4 cm core plugs from various formations, including the Cardium, Viking, Glauconite, Ostracod and Dunvegan C formations found in Alberta, Canada. Reverse nitrogen permeabilities were measured and showed negligible formation damage in all cores.
EXAMPLE VII
A field trial of the fracturing fluid mixture of Example V, without proppant, was conducted on a 450 m well in the Medicine Hat formation. 6 M3 of the mixture comprising 98%
by weight liquid C02 and 2% by weight of a second phase was 20 injected at a rate of about 1.5 m3/min. Production was 16 mcf/d before the treatment and stabilized at 43.4 mcf/d 15 days after the treatme~t.
EXAMPLE VIII
A field trial with the fracturing fluid of Example V was 25 performed in a formation of permeability approaching 1 Darcy.
Only 8 tonnes of proppant were placed but post treatment production was increased twemty-six-fold due to the non-damaging character of the fluid of the invention.
EXAMPLE IX
Field tests of the fluids of Example V, with proppant, were performed on wells in the following formations: Viking, Ostracod, Glauconite, Doig and Niton Sand with permeabilities ranging from 0.1 to about 50 md. Proppant concentrations up to 800 kg/m3 were reached in formations of low permeability.
35 Wells as deep as 2500 m were fractured successfully.

1.301~43 Stabilized production increases up to twenty-fold were recorded.
The viscosities of the mixtures prepared in Examples I, III, IV and V were all found to be higher than would be suggested by simple dilution theory.
The fracturing fluid of the invention normally containing added proppant is introduced into the subterranean formation in the conventional manner used in carbon dioxide fracturing. The fracturing fluid is prepared in a suitable 10 closed mixing apparatus and delivered by means of a high pressure pump into the well bore. After introduction of the calculated volume of fluid, the well bore is shut in for a period adequate to stabilize the fractured formation. After stabilization, the well bore is opened to allow escape of the 15 carbon dioxide gas. The actual fracture of the formation is initiated and propagated by the liquid carbon dioxide/-proppant mixture.
The hydraulic fracturing fluids of the invention, being non-aqueous, are non-damaging to water-sensitive zones within 20 the formation. All of the inherent advantages of a liquid C2 fracture fluid are maintained. The second phase additive is compatible with hydrocarbons and no solid residue is left behind in the underground formation. The viscosity of the fluid is increased over simple C02 systems to provide 25 improved proppant-carrying capacity.
It is to be understood that many changes or modifications of the invention may be made by one skilled in the art, without departing from the spirit or scope of the invention.

Claims

1. A fracturing composition for treating a subterranean formation containing hydrocarbon deposits which composition consists of a liquid/liquid mixture of from 75% to 99.5% by weight of liquid carbon dioxide and 0.5% to 25% by weight of an immiscible organic liquid which does not adversely react with the said carbon dioxide, the subterranean formation or the hydrocarbon therein and a surfactant compatible with the said organic liquid and which organic liquid/surfactant combination imparts to the said liquid carbon dioxide improved properties of viscosity and proppant carrying capabilities.

2. A fracturing composition as claimed in Claim 1 additionally containing a solid propping agent.

3. A fracturing composition as claimed in Claim 1 wherein the said immiscible, organic liquid is selected from the group consisting of (a) crude oil, (b) diesel oil, (c) a solution of triolein and alkoxy-terminated polyglycol, (d) a solution of triolein and a glycol ether, (e) a solution of alcohols having up to 30 carbon atoms and diesel oil, and (f) a solution of alcohols having up to 30 carbon atoms and diesel oil wherein part of the alcohol is replaced with an organic acid having up to 30 carbon atoms, or mixtures of all of these.

4. A fracturing composition for treating a subterranean formation containing hydrocarbon deposits, said composition comprising from 95% to 99.5% by weight of liquid carbon dioxide and from 0.5% to 5% by weight of an immiscible organic liquid which does not adversely react with the said carbon dioxide, the subterranean formation or the hydrocarbon therein, the said immiscible organic liquid containing from 0.1% to 10% by weight of a selected surfactant.

5. A fracturing composition as claimed in Claim 1 or 4 wherein the said surfactant is selected from the group consisting of ethoxylated resin acids, salts of linear alcohol ethoxysulphates and sorbitan oleate.

6. A method of fracturing a hydrocarbon-containing, subterranean formation penetrated by a well bore comprising the steps of:
(a) admixing from 75% to 99.5% by weight of liquid carbon dioxide with from 0.5% to 25% by weight of an immiscible organic liquid which does not adversely react with the carbon dioxide, the subterranean formation or the hydrocarbon therein and from 0.1% to 10% by weight of a selected surfactant;
(b) introducing the said admixture into said well bore and formation at a temperature below the critical temperature of the carbon dioxide and at a pressure to maintain the said admixture as a liquid;
(c) fracturing said formation with said admixture;
(d) maintaining said admixture within said formation sufficiently long to permit said admixture to be volatilized;
and (e) allowing the said fractured formation to stabilize and thereafter opening the said well bore to allow escape of the said volatilized admixture.

7. A method of fracturing as claimed in Claim 6 wherein the said admixture comprises from 95% to 99.5% by weight of liquid carbon dioxide and from 0.5% to 5% by weight of an immiscible organic liquid containing from 0.1% up to 10% by weight of a seleccted surfactant.

8. A method as claimed in Claim 6 wherein the said admixture also contains a solid propping agent.